The present invention relates to improved well fluids that comprise hollow particles, and to methods of using such improved well fluids in subterranean cementing operations.
Subterranean cementing operations are commonly performed in connection with, e.g., subterranean well completion and remedial operations. For example, primary cementing operations often involve the cementing of pipe strings, such as casings and liners, in subterranean well bores. In performing primary cementing, hydraulic cement compositions are pumped into the annular space between the walls of a well bore and the exterior surface of the pipe string disposed therein. The cement composition is permitted to set in the annular space, thereby forming an annular sheath of hardened substantially impermeable cement therein that substantially supports and positions the pipe string in the well bore and bonds the exterior surface of the pipe string to the walls of the well bore. Remedial cementing operations may include activities such as plugging highly permeable zones or fractures in well bores, plugging cracks and holes in pipe strings, and the like.
Hydrocarbon production from a well is often initiated at some time after primary cementing has been completed. Hydrocarbon fluids are often at elevated temperatures as they flow through the well bore to be produced at the surface. Thus, production of hydrocarbons through the well bore towards the surface may transfer heat through the casing into the annular space. This tends to cause any fluids present in the annular space to expand. In wells where annular volume is fixed (e.g., wells having closed and/or trapped annuli), this expansion of annular fluid within the fixed annular volume may increase the pressure within the annulus, sometimes dramatically. This phenomenon, commonly referred to as “annular pressure buildup” (APB), may cause severe well bore damage, including damage to the cement sheath, the casing, tubulars, and other well bore equipment.
An annular space may become trapped (e.g., hydraulically sealed) in a number of ways. For example, an operator may close or trap an annulus by shutting a valve, or by energizing a seal, in such a manner that prevents or inhibits communication between fluids within the annulus and the environment outside the annulus. This may occur, inter alia, towards the end of a cementing operation, when all fluids (e.g., spacer fluids and cement compositions) have been circulated into place to the operator's satisfaction.
Operators have attempted to solve the problem of annular pressure buildup in a variety of ways. For example, operators have wrapped the casing (before its installation into the well bore) with syntactic foam, e.g., foam that comprises small, hollow glass particles that are filled with air at atmospheric pressure. The glass particles may collapse at a certain annular pressure, thereby providing extra volume that prevents or mitigates further pressure buildup within the annulus. However, this possible solution to the problem of annular pressure buildup has been problematic because the presence of the foam wrapping often causes a flow restriction during primary cementing of the casing within the well bore. The foam wrapping has also demonstrated a tendency in some cases to detach from the casing, or to otherwise become damaged, as the casing is installed.
Another method by which operators have attempted to solve the problem of annular pressure buildup has involved the placement of nitrified spacer fluids above the top of the cement in an annulus, to absorb the expansion of annular fluids. However, this can be problematic, because of logistical difficulties such as limited room for the required surface equipment, pressure limitations on pumping equipment and the well bore, and associated costs. Another difficulty associated with this method relates to problems that may be involved in circulating the nitrified spacer into place without losing returns while cementing. This method also may be problematic when cementing operations are conducted in remote geographic areas or other areas that lack sufficient access to certain specialized equipment that may be required for pumping energized fluids (e.g., a nitrified spacer fluid).
Operators have also attempted to address annular pressure buildup by installing one or more rupture disks in an outer casing string. Upon the onset of annular pressure buildup, the rupture disk may be permitted to fail, and thus permit relief of the excess pressure into the formation, rather than into the well bore. This may allow the operator to direct the failure of the casing outward, instead of inward, where it could collapse the casing and tubulars. However, this method is problematic for a variety of reasons, including the difficulty that may arise in placing the rupture disks in a location where communication with a subterranean formation may occur, and the possibility that the casing string may become so compromised after the failure of the rupture disk that future well bore operations or events may be precluded.
Operators also have sought to deal with the problem of annular pressure buildup by intentionally designing the primary cementing operation to provide a “shortfall” of cement, e.g., the top of the cement column installed in an annulus is designed to fall slightly short of the shoe belonging to a preceding casing string. However, this method may create an undesirable structural weakness in the well bore. Furthermore, this method may create the possibility that the designed shortfall undesirably may cause the formation to fracture; the difficulty in precisely determining the magnitude of the formation's fracture gradient may exacerbate this possible difficulty. Additionally, the annulus may become trapped by cement due to channeling that may be caused by poor displacement, or by annular bridging of, inter alia, drill cuttings that may remain in the drilling fluid, and other solids normally associated with drilling fluids (e.g., barite, hematite, and the like).